Southern California Edison unveiled a $582 million program Monday that would step up wildfire safety measures, including a plan to replace nearly 600 miles of its power lines with insulated wire.

In complying with wildfire mitigation plans spelled out in Senate Bill 901, officials for the utility on Monday filed details of its Grid Safety and Resiliency Program with the California Public Utilities Commission.

Edison plans to replace nearly 600 miles of overhead power lines in high fire risk areas with insulated wire by the end of 2020. The move would mark the first large-scale deployment of insulated wire in the U.S. designed to reduce wildfire risk.

While up to 10 percent of wildfire ignitions in California are from power lines, within Edison’s service area more than half of ignitions associated with distribution lines are caused when objects such as metallic balloons, tree limbs and palm fronds come into contact with power lines.

While bare, uninsulated wire meets California state standards and is widely used by utilities across the country, insulated wires can significantly reduce the potential for ignitions resulting from contact with foreign objects.

In addition, insulated wires provide the greatest overall value compared to other mitigation measures such as undergrounding lines.

The utility also wants to make its poles safer. The new poles would be made from “layers of strong glass fibers bonded with epoxy resins.

Under the plan, where appropriate and whenever utility poles are to be replaced, they will be replaced with fire-resistant composite poles that would support the increased weight and diameter of the insulated wire.

Edison also plans to replace about 3,400 miles of overhead line with insulated wire between 2021 and 2025.

Funding for that work would be included in future general rate case requests.

The utility infrastructure would be further improved under the new plan with the installation of fuses and circuit-breaker type devices called remote-controlled automatic reclosers.

Edison is installing 15,700 “current limiting fuses” which would interrupt current more quickly and avoid the potential creation of their own heat source during fuse operation when compared to traditional, industry standard fuses.

The move promises to limit the number of customers affected by an outage.

Use of “reclosers” would stop affected circuits from automatically re-energizing so that work crews can physically inspect the lines before they are re-energized. (The Signal, 9/10/2018)

Gov. Jerry Brown signed a bill that aids Pacific Gas & Electric in covering the costs of last year’s devastating Wine Country wildfires — passing along some of the burden to ratepayers in the process.

The bill, SB 901, will enable PG&E to issue state-authorized bonds to settle more than 200 wildfire-related lawsuits filed by 2,700 plaintiffs against the utility. Higher electricity bills will help repay the bonds.

In June, PG&E said it would post $2.5 billion in charges against its profit to cover losses from the fires.

The law also requires power companies to implement fire prevention strategies by improving their infrastructure and conduction “projects to improve overall forest health and resistance to wildfires,” according to a statement. The higher standards of whether the utilities adequately maintain their power lines will be overseen by the California Public Utilities Commission.

The wildfires that ravaged Northern California in October killed 44 people and destroyed as many as 8,900 structures and 6,100 vehicles. The state tallied nearly $10 billion in commercial and residential insurance claims, with estimates for total damages as high as $15 billion. (San Francisco Business Times, 9/24/2018)

Burning huge amounts of electricity isn’t incidental to bitcoin: instead, it’s embedded into the innermost core of the currency, as the operation known as “mining”. In simplified terms, bitcoin mining is a competition to waste the most electricity possible by doing pointless arithmetic quintillions of times a second.

The more electricity you burn, and the faster your computer, the higher your chance of winning the competition. The prize? 12.5 bitcoin – still worth over $100,000 – plus all the transaction fees paid in the past 10 minutes, which according analysts’ estimates is another $2,500 or so.

This is a winner-takes-all game, where the prize is guaranteed to be paid to one, and only one, miner every 10 minutes. Burning more electricity increases your chances of winning, but correspondingly decreases everyone else’s – and so they have a motivation to burn more electricity in turn.

Cryptocurrencies are electronic forms of money, and bitcoin is one of the most widely distributed and prevalently used cryptocurrencies today. Blockchain is the mechanism used to authenticate cryptocurrencies and all of these concepts are of huge importance to the power industry because the fundamental process behind blockchain, including the creation and use of cryptocurrencies requires significant power usage and it represents a possible trend for the future.

Cryptocurrency requires an immense amount of power to exist. Without tons of energy, there is no Bitcoin. To truly wrap your head around cryptocurrency, you must first understand that the basic economics of it are rooted in energy, not some weird software algorithm. The existence of the algorithm is why it consumes so much energy, and all software improvements to Bitcoin are made with reducing this dynamic in mind. The problem is that a big part of what makes Bitcoin so incredibly secure is its energy consumption.

Blockchain technology is a method of using a network of decentralized computers to validate a transaction using common algorithms and creating a unique encrypted identifier or block, which is added to a string of records (a chain of blocks) associated with that transaction, thereby creating an incorruptible digital record. Blockchain technology was originally created to document cryptocurrency transactions, but it is recognized to have potentially unlimited potential for other uses. Those uses include supply chain records, stock transactions, financial transactions beyond cryptocurrencies, crowdsourcing, real estate records management and more. Major retailers, banks and software companies are closely monitoring the advancement of blockchain technology.

Of all the uses for blockchain technology, its application to cryptocurrencies is the most prevalent. Cryptocurrencies exist only in the Ethernet. They have no intrinsic value like the old U.S. currencies made of gold or redeemable for silver; supply is not controlled by a central bank or government; and they have no physical form. That is why the creation of unique and nearly impossible-to-fudge digital records for cryptocurrencies is so important. And it is not just an intellectual exercise. The estimated annual revenue associated with the creation of the most common cryptocurrency, bitcoin, is roughly $7 Billion. Plus, there are more than 1000 additional cryptocurrencies on the web.

So why are cryptocurrencies and blockchain technology of importance to the power industry? It’s simple. Creating and validating a cryptocurrency, say a bitcoin, requires significant computing power to run mathematical algorithms. Remote computer systems extensively involved in so called “mining” for bitcoin or solving the equations that document a new piece in the digital records of the currency require power to run and disperse heat. When cryptocurrencies were just a novelty, the computer power needed was insignificant. Today, data centers and even extensive server farms that draw 10’s of megawatts are required for large operations. Estimates of the energy use for bitcoin creation, likely the most common cryptocurrency, range from 14 to 57 TWh annually, worldwide. Operations develop where power is cheap and major mining operations may favor cooler regions where computer system cooling costs will be less.

Just a few years into the cryptocurrency revolution, bitcoin mining is already eating up an estimated 20,000 gigawatt hours of electricity per year. That’s roughly .1% of global generation, on par with the power demand of Ireland. The primary culprits are bitcoin mining appliances like the Antminer S9, which is a computer processor that does nothing but endlessly crunch algorithms to lengthen the blockchain. An Antminer draws a load of 1.5 kilowatts — enough to power two refrigerators and a flatscreen TV. If you run an Antminer 24/7 for a year it will produce about 0.85 bitcoins, at a cost of about 15,000 kilowatt hours. Depending on your power prices it will cost anywhere from $600 (at 3 cents per Kwh) to $1,800 (at 9 cents per Kwh) to mine one coin. Even with bitcoin having plunged to $11,600 this morning, there’s still money to be made, assuming you can get your machines cheap enough. Walmart sells the Antminer s9 for $8,200.

The electricity consumption needed to “mine” cryptocurrencies this year will outpace global electric vehicle demand according to some reports. This growing increase for power has brought energy usage to the forefront of the crypto conversation. Even a slight edge in terms of computational power can help miners win a larger share of the distributed rewards, which has prompted a race to build more powerful and more energy-consuming mining computers. At the same time, the Bitcoin network keeps making calculations harder to solve, necessitating more and more power to secure the same rewards.

It’s hard to make reliable calculations because mining facilities tend to keep their operations behind closed doors. But some research claims the entire Bitcoin network could consume as much as 7.7 gigawatts of electricity by the end of this year—enough to power a country the size of Austria.

Cryptocurrency mining’s massive energy consumption may be leaving a big carbon footprint too. The network is mostly fueled by power plants in China where coal-based electricity is available at very low rates. This results in an extreme carbon footprint for each unique Bitcoin transaction.

Russia is our biggest competitor in the international natural gas market. They are proposing to build Nord Stream 2, a 48- inch natural gas pipeline that will run from near St. Petersburg in Russia to Greifswald in northeastern Germany. It would run under the Baltic Sea parallel to Nord Stream 1, which was built in 2011. Russia is already supplying most of Germany’s natural gas. This pipeline will double the amount of gas Germany can import from Russia. Germany currently uses more natural gas than any other European country and they expect their natural gas demand to increase. This is a major win for Gazprom, the Russian natural gas company.

Gazprom has been providing natural gas to Europe for over 40 years. They are the largest exporter of natural gas to the European market. The US entered this market last year with natural gas shipments Poland. Natural gas demand in Europe is expected to continue to increase.

European natural gas production is decreasing. Most counties have banned or restricted hydraulic fracturing, which is required on almost every well in order to produce natural gas or oil. These countries are turning to Russia for their natural gas needs. Russia, like all countries, fracks almost every well. Mr. Putin will continue to frack and make billions of dollars from Europe. Gazprom’s contracts with its European customers are long term and tied to oil prices.

Shale Crescent

America can compete in Europe but Russia has an advantage with their pipeline over our LNG. However, our competition will force Russia to stay competitive, like what happened in Poland when the US started shipping them LNG last summer. Gazprom now has some competition from the USA.

The other problem Europe has by getting gas from Putin and Gazprom is that Putin can apply political pressure, if he chooses, like he did in Ukraine in 2014 and simply close the valve, shutting off their natural gas.

Natural gas prices in the USA are not tied to oil prices. The current Dominion South Pointe price for natural gas in the Shale Crescent USA is $2.40 per MM BTU. This is equivalent to oil at $14.40 per barrel. Oil on the world market is selling for $70 per barrel. (The Parkersburg News and Sentinel, 7/28/2018, Shale Crescent USA)

Marcellus shale has become one of the world's largest natural gas fields and the Utica Shale - located a few thousand feet below the Marcellus - has become a new drilling target. Marcellus Shale occurs in the subsurface beneath much of Ohio, West Virginia, Pennsylvania and New York. Small areas of Maryland, Kentucky, Tennessee and Virginia are also underlain by the Marcellus Shale.

Utica shale underlies significant portions of Ohio, Pennsylvania, West Virginia, New York, Quebec and other parts of eastern North America. In the subsurface, the Utica Shale is located a few thousand feet below the Marcellus Shale.

The United States Geological Survey's mean estimates of undiscovered, technically recoverable unconventional resources indicate that the Utica Shale contains about 38 trillion cubic feet of natural gas, about 940 million barrels of oil, and 208 million barrels of natural gas liquids.

Of course, It is difficult to estimate the amount of gas in a rock unit that varies in thickness, composition and character, and is located thousands of feet below Earth's surface.

The Utica Shale has not been extensively developed for two reasons: 1) its great depth over much of its geographic extent, and, 2) its limited ability to yield gas and oil to a well because of its low permeability. This is starting to change as horizontal drilling and hydraulic fracturing are used to stimulate production. These methods were not extensively used in the Utica Shale prior to 2010.

In central Pennsylvania, the Utica can be up to 7000 feet below the Marcellus Shale, but that depth difference decreases to the west. In eastern Ohio the Utica can be less than 3000 feet below the Marcellus. Most of the drilling activity in the Utica Shale has occurred in eastern Ohio. Most of the shale drilling activity in Pennsylvania has targeted the Marcellus Shale, which is above the Utica Shale. (Geology.com, Geology.com) https://geology.com/articles/utica-shale/

Shell built the world’s second floating LNG facility in 2013. Prelude weighs in at 600,000 tonnes, which is six times the weight of the world's largest aircraft carrier. Prelude, a "floating liquefied natural gas facility" is 1,600 feet long and 243 feet wide. That makes it the biggest ship in the world.

As a floating natural gas facility, it will be anchored off the coast of Western Australia for 25 years, acting more like a platform than a mobile vessel. The ship will be anchored to the sea floor with a 93-metre-tall turret while it processes 175 Olympic swimming pools' worth of liquid natural gas year-round.

Gas will be harvested from the ocean, processed on board and then transferred to transport ships. The ship could be supplied by pipelines from the mainland. In the past, offshore gas had to be piped onto land and liquefied in shore side plants. But with the mega-ships, offshore LNG can be processed on site.

Prelude has three 6,700-horsepower engines, giving it the combined power of about 152 cars. The ship floated out of dry dock for the first time in late November 2013. It began its job off the coast of Western Australia in 2017.

Preludewas built by the Technip /Samsung Consortium (TSC) in South Korea for a joint venture between Royal Dutch Shell, KOGAS and Inpex. It was made with more than 260,000 tonnes of steel. At full load, it will displace more than 600,000 tonnes, more than five times the displacement of a Nimitz-class aircraft carrier. The hull was launched in December 2013.

The main double-hulled structure was built by the Technip Samsung Consortium in the Samsung Heavy Industries Geoje shipyard in South Korea.

Prelude FLNG was approved for funding by Shell in 2011. Analyst estimates in 2013 for the cost of the vessel were between US$10.8 to 12.6 billion. Shell estimated in 2014 that the project would cost up to US$3.5 billion per million tons of production capacity.

The Prelude FLNG system will be used in the Prelude and Concerto gas fields in the Browse LNG Basin, 120 mi off the coast of Australia; drilling and gas production are both expected to begin in 2016. It has a planned life expectancy of 25 years. The Prelude and Concerto fields are expected to produce 5.3 million tonnes of liquid and condensate per year; this includes 3.6 million tonnes of liquified natural gas, 1.3 million tonnes of condensate, and 400,000 tonnes of liquified petroleum gas.

Natural gas will be extracted from wells and liquefied by chilling it to −260 °F. The ability to produce and offload LNG to large LNG carriers is an important innovation, which reduces costs and removes the need for long pipelines to land-based LNG processing plants.

On July 25, 2017, after a journey of 3,600 miles from its construction site in South Korea, Prelude arrived on site in Western Australian waters. It will begin its hook-up and commissioning phase, and is expected to become operational in 2018. (Fast Company, 10/12/2009, News.com, 12/9/2013, Wiki)

The United States is the world’s biggest natural gas producer, yet environmental lawsuits by states, green groups and property owners have tied up pipeline construction. This is making it difficult to get shipments to some regions, including fuel-hungry New England. America needs new regulations or laws that favor reasonable approval of pipelines. In fact, pipeline infrastructure obstruction is a national security issue that puts our country at risk.

The administration of President Donald Trump has said that constraints on pipelines and other energy infrastructure can trigger price spikes and pose a risk to national security but has yet to intervene in state or local-level permitting issues. U.S. Energy Secretary Rick Perry agrees that New York’s efforts to stop new pipelines could pose “a national security issue that outweighs the political concerns in Albany, New York.”

President Trump could invoke the Defense Production Act to accelerate pipeline approvals based on national security. This is a draconian measure, but draconian measures are needed when our national security is at risk.

The United States needs to have the capability to neutralize Russia's natural gas stranglehold on Europe. The USA can do that by exporting liquefied natural gas (LNG). Yet, without the pipelines to get our natural gas reserves to ports, such leverage is not possible. Russia would also like to get Japan hooked on its natural gas and is building a pipeline to do just that. Again, we need to have the ability to compete with Russia in delivering natural gas to Japan. The industry is now eyeing growing export markets by investing in facilities that can liquefy gas for shipment overseas. The United States has sent cargoes to nearly 30 countries in the past year.

America cannot afford blackouts, principally because it puts our security at risk. Nuclear power plants and coal-fired power plants are closing at record rates and are being replaced with natural gas plants. Base load power plants burn a mind boggling amount of natural gas to make up for nuclear and coal. If we do not have the pipeline capacity to deliver the natural gas to the plants, we will inevitably have blackouts and brownouts. This is unacceptable in our internet age. Right now gas from the Marcellus and Utica shale is being blocked by some neighboring states, which cuts off markets in New England.

Pipeline projects that are under construction are getting held up by judges in lawsuits and this needs to be addressed. Absent a Defense Production Act pathway, it might have to be addressed either by the U.S. Federal Energy Regulatory Commission (FERC) or with legislation. FERC oversees construction of new pipelines. FERC in April asked stakeholders to submit comments on whether the commission should revise existing pipeline approval policies, yielding feedback from industry backers.

In recent weeks, environmental groups like the Sierra Club have won court orders delaying construction on EQT Midstream Partners LP’s Mountain Valley pipeline at several locations in West Virginia, and are now seeking a court order to also stop construction in Virginia. Mountain Valley is one of several pipelines under construction to move gas from the Marcellus and Utica shale formations in Pennsylvania, West Virginia and Ohio to consumers in the Southeast, Gulf Coast and Midwest.

Production in the Marcellus and Utica, the biggest shale gas formations in the United States, has ballooned to 28.9 billion cubic feet per day (bcfd) from 1.5 bcfd a decade ago, according to federal energy data. One billion cubic feet is enough to fuel about 5 million U.S. homes for a day.

Polar vortex weather in the winter or a cyber attack could threaten to leave Wall Street in the dark and hospitals without power. In January, gas prices soared to a record high due to pipeline constraints during an extreme cold spell that forced power generators in New England to resort to burning diesel and Russian imported LNG. (Reuters, 6/28/2018)

PRESIDENT'S CORNER

By Norris McDonald

It was refreshing to see the New York Post article about a recent paper by Matthew C. Nisbet, a communications professor at Northeastern University, that examined the climate-change and energy grants given by 19 green-leaning philanthropies — including familiar names like the Hewlett, Kresge and MacArthur foundations. His conclusion: America’s biggest environmental groups seldom, if ever, talk about the climate-change benefits of nuclear energy. Why not? There’s no money in it.

As the first environmentalist to publicly and aggressively support nuclear power in the climate change and global warming era, I can testify that Professor Nisbet's conclusion is absolute true. I have been working as a pro-nuclear environmental activist for 18 years and I can barely pay my rent. I also seriously doubt that my recommendation to the nuclear industry to start funding the environmental groups to support nuclear power will be adopted because they probably are not willing to put up the tens to hundreds of millions of dollars it would take to get them to acknowledge the obvious: that nuclear power is the best weapon against global warming.

Here are some of the findings from his paper:

Between 2011 and 2015, the 19 foundations made 2,502 grants totaling nearly $557 million to environmental groups like the Sierra Club (the largest single recipient, with nearly $49 million in grants), Natural Resources Defense Council and Environmental Defense Fund.

Of that $557 million, the big environmental groups received nearly $187 million to promote renewable energy and efficiency. They got another $92.5 million for “climate change-related communication, media and mobilization” and nearly $82 million to oppose hydraulic fracturing and to “promote actions to limit/oppose [the] fossil fuel industry.” But “no grants were focused on promoting nuclear energy, though $175,000 in grants were devoted to opposing nuclear energy for cost and safety reasons.”

To underscore: Over a five-year period, some of America’s biggest foundations doled out more than half a billion dollars to some of America’s biggest environmental groups and not a penny was spent promoting nuclear energy, even though nuclear provides about 20 percent of US electricity and twice as much emissions-free juice as all US solar and wind, combined.

Why would any of the large environmental groups risk losing many millions of dollars to support correct science as it relates to nuclear power and global warming? Nisbet’s paper is important because it exposes the anti-nuclear orthodoxy that prevails at some of America’s biggest philanthropic groups. Just as important, it shows that those same philanthropic groups are ignoring the conclusions of the world’s top climate scientists.

President Donald Trump ordered his Energy Secretary Rick Perry to take immediate action to stem power plant closures, arguing that a decline in coal and nuclear electricity is putting the nation’s security at risk. Impending retirements of fuel-secure power facilities are leading to a rapid depletion of a critical part of our nation’s energy mix and impacting the resilience of our power grid. The Center supports President Trump's order and we look forward to promoting Energy Secretary Rick Perry's recommendations.

Under the Energy Department’s draft plan, the administration would take action under two laws: the Federal Power Act that allows the government to guarantee profits for power plants amid grid emergencies, and the 68-year-old Defense Production Act, a Cold War-era statute once invoked by President Harry Truman to help the steel industry.

For two years, the Energy Department would direct the purchase of power or electric generation capacity from a designated list of facilities “to forestall any future actions toward retirement, decommissioning or deactivation,” according to the memo. The proposed Energy Department directive also would tell some of those facilities to continue generating and delivering electric power according to their existing or recent contracts with utilities.

It’s not clear that the Federal Energy Regulatory Commission would go along with the plan. Although the administration could aim to bypass the electric regulators completely, FERC could play a role in any effort to require grid operators to make out-of-market payments to electric generators.

Trump’s directive comes as administration officials search for ways to extend the life of money-losing coal and nuclear power plants that face competition from cheaper natural gas and renewable energy. The plants are considered “fuel-secure” because they house coal and nuclear material on site and are not dependent on pipelines that can be disrupted, wind that stops blowing or a sun that sets.

The department’s strategy, outlined in a memo that would use authority granted under a pair of federal laws to establish a “strategic electric generation reserve” and compel grid operators to buy electricity from at-risk plants. The steps are necessary to protect national security.

The move comes as Trump uses similar national security arguments to justify market interventions aimed at protecting other treasured political constituencies -- steelworkers and automakers -- at the expense of U.S. allies.

On May 10, 2018, the House approved a bill (H.R. 3053 - Nuclear Waste Policy Amendments Act of 2017) to revive the mothballed nuclear waste dump at Nevada’s Yucca Mountain. The bill would help solve a nuclear-waste storage problem that has festered for more than three decades. The House approved the bill, 340-72, sending the measure to the Senate, where Nevada’s two senators have vowed to block it.

More than 80,000 metric tons of spent fuel from commercial nuclear power plants sit idle in 121 communities across 39 states.

The bill directs the Energy Department to continue a licensing process for Yucca Mountain while also moving forward with a separate plan for a temporary storage site in New Mexico or Texas.

This bill amends the Nuclear Waste Policy Act of 1982 to direct the Department of Energy (DOE) to initiate a program to consolidate and temporarily store commercial spent nuclear fuel during the development, construction, and operation of a permanent nuclear waste repository.

The bill addresses federal land withdrawal and related management issues, including the permanent withdrawal of specific federal land for repository use by DOE, updating the Nuclear Regulatory Commission licensing process and conditions for the repository, and limiting activities relating to developing a separate defense waste repository used for storing high-level radioactive waste and spent nuclear fuel derived from the atomic energy defense activities of DOE.

DOE may enter into agreements to provide benefits to state, local, and Tribal governments that might host or be affected by facilities related to storing nuclear waste.

The bill revises the method by which DOE funds its nuclear waste management activities though the collection and usage of the Nuclear Waste Fund.

FirstEnergy has placed its coal and nuclear generation units under chapter 11 bankruptcy. Two days before FirstEnergy's bankruptcy filing, the company petitioned the Department of Energy (DOE) for an emergency bailout, citing concerns abou reliability. The petition could reinvigorate a debate started by Energy Secretary Rick Perry, who last year to change how coal and nuclear plants are compensated for their power. The rule was denied by the Federal Energy Regulatory Commission(FERC), which said that there was not enough evidence to justify changing how coal and nuclear are compensated.

In FirstEnergy's petition, it asked the DOE to require East Coast grid manager PJM to buy power from its coal and nuclear plants and to have PJM compensate those plants for "the full benefits they provide to energy markets and the public at large." That language mirrors the language of the rule Perry proposed in 2017, which would have allowed any coal or nuclear plant with more than 90 days of fuel onsite to seek “full recovery of costs.”

Although FERC denied Perry's proposed rule in January, FirstEnergy is banking that Perry, and by extension the Trump administration, would be willing to issue an emergency order to keep its plants running under Section 202(c) of the Federal Power Act. According to the DOE, that rule is meant to ensure grid operations during emergencies. (ARSTechnica, 4/1/2018)

FirstEnergy says it is getting out of the nuclear power business within the next three years. The company's power plant subsidiaries FirstEnergy Solutions and the FirstEnergy Nuclear Operating Co. late Wednesday informed the Nuclear Regulatory Commission and regional grid manager PJM Interconnection that it will close its nuclear power plants within three years. The companies plan to close the Davis-Besse nuclear power plant near Toledo in 2020, and both the Perry nuclear plant in Lake County as well as the two-reactor Beaver Valley nuclear plant near Pittsburgh in 2021.

The companies made no mention of filing for bankruptcy. Closing the nuclear plants years from today does nothing to alleviate the heavy debt FirstEnergy Solutions has amassed -- more than $2.8 billion to creditors and another $1.7 billion to the parent company FirstEnergy Corp. FirstEnergy Solutions has a $100 million debt payment due in the first week of April.

The companies are still looking for a way to avoid an immediate bankruptcy if it can secure extra funding for its nuclear plants from Ohio and Pennsylvania. So far, lawmakers have ignored FirstEnergy's pleas for special nuclear subsidies.

With a total generating capacity of more than 4,000 megawatts, the three power plants in 2017 generated about two-thirds of the electricity that the companies produced. They also contributed more than $540 million in local taxes and provided jobs for about 2,300 people.

In 2016 the company began circulating a pamphlet among Ohio lawmakers proposing its nuclear plants get extra funding from customers -- $300 million extra annually -- because they don't produce any carbon dioxide. The "zero emission credits" were modeled on similar programs in Illinois and New York for certain nuclear plants.

Legislation creating the "ZECs" for FirstEnergy's plants has languished in House and Senate committees for more than a year. And Jones has said he thought bankruptcy would be unavoidable, though he has stressed such a decision would be up to FirstEnergy Solutions, and not the parent company. (Cleveland.com, 3/28/2018)

The 2-year budget bill passed last night extends the Nuclear Production Tax Credit.

The 2005 Energy Policy Act provided a tax credit of 1.8 cents per kilowatt-hour for electricity produced from new reactors, but set a deadline of 2020 for the plants to be in service. The new bill removes that deadline, which would ensure that the two Westinghouse AP1000 reactors being built at Southern Nuclear Operating Company's Vogtle site in George could benefit from the credit.

Center President Norris McDonald at signing of Energy Policy Act of 2005

[Note: The Center worked diligently for the passage of the Energy Policy Act of 2005 and particularly for the inclusion of the Nuclear Production Tax Credit. It was for this work that Center President Norris McDonald was invited to attend the signing of the legislation as a Special Guest of The White House in Albuquerque, New Mexico].

Unforeseen events—the Chapter 11 filing by Westinghouse, regulatory delays associated with first-of-a-kind engineering projects, and Fukushima—will result in the units coming online after 2020, therefore missing the opportunity to receive the PTC.

The tax credit is applicable to the first 6,000 megawatts of new nuclear capacity that come online. The completion of Vogtle 3 and 4 will leave a significant amount of remaining capacity that future small modular or advanced reactor projects will be able to access.

The small modular reactor design closest to construction is from NuScale Power LLC, which in January became the first to submit a design certification application to the U.S. Nuclear Regulatory Commission. NuScale plans to build a first commercial power plant at the U.S. Department of Energy’s Idaho National Laboratory, owned by Utah Associated Municipal Power Systems and operated by Washington state-based utility Energy Northwest. It is expected to begin commercial operations by 2026. (NEI, 11/2/2017, Background/NEI, Greentech Media, 2/9/2018)

Wind power is forecast to surpass hydroelectricity for the first time as the nation’s top source of renewable electricity sometime in the next year, according to the U.S. Energy Information Administration.

The sector is expected to produce 6.4 percent of utility-scale electricity in 2018, and 6.9 percent in 2019, propelled by a construction boom of new turbines across the country.

EIA: A chart from the Energy Information Administration shows the rapid growth of wind energy generation since the early 2000s.

Few new hydropower plants are in the works, so new electricity generation depends on how much rainfall and water runoff pools in existing dams and reservoirs. Hydropower provided 7.4 percent of utility-scale generation in 2017 ― a particularly wet year ― but that figure is projected to fall to about 6.5 percent in 2018 and 6.6 percent in 2019.

The news marks a new milestone in wind’s steady rise. Wind energy usurped hydropower’s generating capacity for the first time in February 2017 as turbine installations tripled from 2008.

The United States is projected to gain 37 gigawatts of new wind capacity between 2017 and 2020, according to Bloomberg New Energy Finance. The share of capacity increases each year, from 7 gigawatts in 2017 to a projected 11 gigawatts in 2020.

Part of what’s driving the boom is a rush to build turbines to get the full benefits of the production tax credit. Congress extended the subsidy, which has been in place since the early 1990s, for five years in 2015. But the credit began phasing down by 20 percent in 2017, kick-starting a dash to build as many turbines as possible before the federal benefit expires.

Yet states are expected to continue providing incentives for wind energy long after 2020. The offshore wind industry ― a popular form of energy in Europe, though currently limited in North America to five turbines off the coast of Block Island, Rhode Island ― is only expected to gain steam after 2021, according to BNEF. For example, in New York, where the state plans to get half its electricity from renewables in 12 years, a series ofprojects off the coast of Long Island are expected to provide 2.4 gigawatts of energy by 2030, enough to power 1.25 million homes. (Huff Post, 11/24/2018)

North America’s first offshore wind farm, Block Island Wind Farm, started operations in November 2016 and includes five wind turbines that tower 589 feet above the sea and power the homes of the island’s 1,000 year-round residents. . When it is running at full capacity, the farm will generate enough electricity to power 17,000 homes, or about 4 percent of all households in Rhode Island.

Cape Wind, a 130-turbine offshore wind farm planned five miles to the north off the coast of Massachusetts, was supposed to be the first in the country. That project was proposed in 2001 ― but for numerous reasons, has never actually gotten started and probably never will. Cape Wind’s struggles provided an instructive example of what not to do for Deepwater Wind, the Providence-based developer behind Block Island farm.

Where Cape Wind’s blueprints went big with 468 megawatts of power, Deepwater aimed for a more modest 30 megawatts. Cape Wind estimated its costs at $2.5 billion, while Deepwater came in at about $300 million. Block Island Wind Farm also had a smaller footprint and fewer, less powerful opponents to win over. Cape Wind has famously drawn opposition from people with surnames like Kennedy and Koch, who didn’t want windmills obstructing their beachfront views. Environmentalists, too, feared noise from the construction could disturb migrating whales.

Deepwater Wind also had another advantage over Cape Wind: Its CEO, Jeff Grybowski, was previously chief of staff to former Rhode Island Gov. Donald Carcieri (R) and had access to state officials he’d later court for his wind project. It took seven years to complete the project, and Grybowski said he spent six of them navigating the Byzantine web of government agencies whose approval he needed.

Grybowski did have obstacles. Environmentalists had some of the same concerns about Block Island Wind Farm that they had about Cape Wind, and the project was halted for weeks to avoid harming right whales swimming north in the early spring months. Some on Block Island still complain that the turbines, roughly twice the height of the Statue of Liberty, are an eyesore.

There was also deep skepticism from Rhode Island’s fishing industry. Overfishing and climate change had already hammered local populations of winter flounder and lobster ― leading to strict new catch limits to preserve the future of those species and new struggles for the industry. The proposed wind farm seemed like another unwelcome development that could interfere with fishing.

Wind industry leaders hope Block Island Wind Farm signals the beginning of a boom offshore. There are already 13 other projects in various stages of development around the country, most of them in federal waters far offshore rather than in areas under state control. Massachusetts Gov. Charlie Baker (R) signed a bill in August that requires utilities in that state to buy up to 1,600 megawatts of power from offshore wind developers. That same month, New York Gov. Andrew Cuomo (D) announced plans for his state to draw half of its power from renewable sources by 2030. Both of those policies are expected to help the offshore wind industry take off.

Deepwater Wind is already leasing two more parcels of land totaling 164,750 acres off the coast of Rhode Island and Massachusetts, which it plans to develop into a much larger, utility-scale farm with up to 200 turbines. By next spring, it also plans to send oceanographers to survey an area off the coast of Long Island where they hope to build a 15-turbine, 90-megawatt farm.

The firm wants to connect the Long Island farm to its bigger farms to the north through a transmission cable, creating a wind energy network along the Northeast coast. Unlike Block Island Wind Farm, which is nestled close to Block Island, the other farms will be located up to 25 miles offshore, where winds tend to be much stronger and more reliable.

The biggest obstacle to developing offshore wind energy may be its price. Deepwater Wind chose the site three miles off Block Island in part because of the island’s high energy prices. Residents had relied on electricity produced from burning diesel, paying upward of 50 cents per kilowatt hour in the summer ― 287 percent more than the average American.

Deepwater Wind estimates that drawing from their power will lower residents’ power bills 40 percent. But that’s partly because mainland Rhode Islanders are footing the bill.

The company brokered a 20-year deal to sell National Grid wind power at 24.4 cents per kilowatt hour ― more than twice the price the utility pays for energy now. What’s more, the deal is written to allow a price increase of 3.5 percent per year. By the time the agreement expires, National Grid will be paying a rate of 50 cents per kilowatt hour to Deepwater Wind, a cost likely to be passed on to ratepayers in the state as a price increase.

For Deepwater Wind and its chief investor, that means a handsome payday. The project could generate more than $900 million in profit, according to calculations by Forbes, and that’s before you factor in $100 million in federal tax credits allotted to clean energy projects.

Another challenge may be the supply chain for turbine components, most of which did not come from Rhode Island. For these five turbines, Deepwater Wind enlisted General Electric to build the 240-foot blades in Denmark, while the nacelles, which house the gears and engines, are built in France. About 300 laborers from Rhode Island were joined by offshore rig workers from Louisiana, where the steel bases for the towers were built. The cable that connects the farm to shore came from South Korea.

Still, tiny Rhode Island — and its total population of 1 million; eight times smaller than New York City ― wants to be a pioneer in the U.S. offshore industry. (Huff Post, 11/3/2016)

Prepare fire prevention plans, take other steps to mitigate fires in high-risk zones, and

Establishes a High Fire-Threat District map to inform where these actions are needed most.

This new policy includes significant new fire-prevention rules for utility poles and wires, including major new rules for vegetation management. The map includes a broader definition of fire threat and also shows how dramatically climate impacts are increasing fire risks -- land that is covered in the elevated, high and tree mortality fire hazard areas has grown from 31,000 square miles to 70,000 square miles. That’s 44 percent of California’s total land area.

Utilities would also be given greater authority to disconnect customers who refuse to allow crews to remove trees on their property that pose a fire risk. The new regulations will affect a newly established designation of land in California, the “high fire-threat district.” A detailed map, developed in concert with the California Department of Forestry and Fire Prevention, will show areas of the state with an elevated fire risk. The maps are expected to be finalized sometime next year.

Utilities will be required to increase the minimum clearance between electrical equipment, including power and transmission lines, and trees and other vegetation. Utilities would also be given greater authority to disconnect customers who refuse to allow crews to remove trees on their property that pose a fire risk.

Southern California has been under siege from multiple wildfires, pushed by the fiercest Santa Ana winds to hit the region in a decade. The Thomas Fire --the largest and most destructive fire currently raging in the region -- grew to 250,000 acres and claimed the life of a young fire engineer.

SDG&E sought to recover $379 million, which represents a portion of the $2.4 billion in costs and legal fees the utility incurred to resolve third-party damage claims from the Witch, Guejito and Rice wildfires. In all three cases, SDG&E was found guilty of imprudent management.

For investor-owned utilities, the inability to recover costs from a natural disaster presents a fundamental business risk. How can California utilities continue to attract smart investment if there’s a fear in the investment community that there might be an undue risk associated with their ability to recover a fair rate of return because of wildfires?

It is unfair to put the burden squarely on energy companies for this reason because fires are a societal issue. It’s an issue that involves better forest management, more resources and training for the first-responder community, and possible changes to building codes and land-use planning. Utilities also need to come up with new ways to prevent fires and ensure grid resilience. (Green Technology Media, 12/18-2017, San Francisco Chronicle, 12/28/2017)

SoCal Edison has admitted they are under investigation for possibly being the cause of one or more wildfires around Southern California that broke out last week. Investigators say the utility company had equipment near where one of the fires started and are not ruling it out as a cause. The Thomas Fire near Santa Barbara is in its second week and still only 25 percent contained. Cal Fire and other agencies are not yet giving details into the probe.

Socal Edison released this statement:

The causes of the wildfires are being investigated by Cal Fire, other fire agencies and the California Public Utilities Commission…SCE believes the investigation now includes the possible role of its facilities.

A Socal Edison spokesperson would not say which fires they are under scrutiny for but said it’s more than one.

Investigators will go over 911 calls and backtrack to where the fires started. They’re acknowledging their equipment is in those areas, but they’re not acknowledging they started those fires.

California has a history of wildfires started by winds pushing trees into power lines. In 2007, SoCal Edison was fined for the Malibu fires. In Northern California, PG&E is being investigated for the possible cause of recent fires. (CBS Los Angeles, 12/12/2017)

Electric utilities in California want ratepayers to pay for lines destroyed by wildfires but do not appear to be in a hurry to share their transmission and distribution line maps. We think a nice compromise might be to share those maps in exchange for ratepayer support for line replacement and a utility-led wildfire prevention program that would use firebreaks because they already have the right-of-ways. State legislation would still be needed to expand cutting in these utility line right-of-ways (we need about a one-mile firebreak in wildfire areas. Professionals in the wildfire area could work with utilities to prepare a grid that would be effective in preventing these very destructive wildfires.

The Center has a Wildfire Mitigation Program that provides a road map for how the State of California could design a program for wildfire prevention. Because of the convoluted nature of such a program, state legislation is needed to design such a complex program. This is because there is no profit for insurance companies in wildfire prevention and only budget cuts for state agencies that would reduce wildfires.

Utilities should embrace wildfire prevention as part of their utility line replacement. This support could also be an important pathway for wildfire prevention legislation approval since utilities are already lobbying to get approval for line replacement. Utilities also already have the equipment in place to implement expanded firebreaks along their transmission and distribution line network. Their efforts could be supplemented by state program equipment and personnel.

We can prevent these devastating wildfires, but there is no incentive to do so. All of the incentives are on the fire fighting side of the equation. Yet that equation is devastating for the residents of California who live in wildfire areas.

PRESIDENT'S CORNER

By Norris McDonald

The 2017 wildfire season in Northern California has led me to address the unwillingness of the state to adequately address wildfire prevention. The Center thoroughly researched this issue in 2011 and found that wildfire prevention falls between the cracks, particularly in comparison to the Wildfire Industrial Complex (WIC), which includes the insurance companies, state agencies and fire departments. The primary attention is placed on fighting fires and not on preventing them. The CenterWildfire Mitigation Program is designed to address uncontrollable wildfires. We were promoting a wood chip to energy program that would utilize the cut wood in wildfire areas to produce electricity. In meeting with the California Department of Insurance, we realized that there was no practical way to include wildfire prevention in the rate approval process.

Our primary solution to wildfires is the firebreak. Strategically placed firebreaks could prevent the vast majority of wildfires. We discovered that there is no institutional structure or combination of institutional structures that can approve a firebreak prevention program.

The California Department of Insurance regulates insurance rates through its Rate Regulation Branch. The Rate Regulation Branch (RRB) determines whether rates charged to consumers in California are fair (not excessive, inadequate or unfairly discriminatory). RRB analyzes filings submitted by property and casualty insurers and other insurance organizations under California's prior approval statutes for most property and casualty lines of business. In addition, the RRB analyzes filings submitted by property and casualty insurers and other insurance organizations under California's file and use statutes for a limited number of property and casualty lines of business.

Unfortunately, there appears to be no incentive for insurance companies to engage in wildfire prevention,. Where is the constituency or client base requesting or willing to pay for such a service. It does not exist. In other words there is no profit in wildfire prevention. And this is tragic considering that this year's wildfire season took an number of lives and property, it is amazing that there is little to no efforts being given to preventing these disasters.

Approximate 40 lives have been lost, hundreds of people are still listed as missing, hundreds of thousand of acres have been scorched, and thousands of homes and businesses have been lost. One would think that there would be more serious consideration given to preventing these disasters than sitting back and preparing to go through it all over again. State agencies address fire prevention efforts but the firebreak solution does not appear to be seriously considered.

The California Department of Forestry and Fire Protection (CAL FIRE) is dedicated to the fire protection and stewardship of over 31 million acres of California's privately-owned wildlands. In addition, the Department provides varied emergency services in 36 of the State's 58 counties via contracts with local governments. The Department's firefighters, fire engines, and aircraft respond to an average of more than 5,600 wildland fires each year. Those fires burn more than 172,000 acres annually.

As part of the CAL FIRE team since 1995, the Office of the State Fire Marshal (OSFM) supports the CAL FIRE mission to protect life and property through fire prevention engineering programs, law and code enforcement and education. The OSFM provides for fire prevention by enforcing fire-related laws in state-owned or operated buildings, investigating arson fires in California, licensing those who inspect and service fire protection systems, approving fireworks as safe and sane for use in California, regulating the use of chemical flame retardants, evaluating building materials against fire safety standards, regulating hazardous liquid pipelines, and tracking incident statistics for local and state government emergency response agencies. The OSFM, State Fire Training, and CAL FIRE Academy programs provide training education and certification programs for the California Fire Service.

We understand that hundreds of miles of one mile wide firebreaks is well beyond the powers of any one or even multiple agencies to regulate, so the state legislature needs to design and pass legislation to design a wildfire firebreak program that can prevent these devastating wildfires.

In recent years, many states have adopted a deregulated energy market that allows residents to shop for the supply portion of their energy rather than automatically getting it from their utility – a right known as energy choice. Deregulation changed the world of energy, which is reflected in price differences across regulated and deregulated energy markets. Here, we’ve compiled data to show you just how much energy costs can vary, including historical energy supply prices from the U.S. Energy Information Administration (EIA) in all 50 states. Information on recent rates and fluctuations may help you understand your bill or decide to change your energy supply plan.

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